It is well known to provide non-linear subterranean well bores by way of directional drilling. When carrying out directional drilling, fluctuations in the weight-on-bit (WOB) and resulting fluctuations in the torque-on-bit (TOB) can cause the orientation of the drill bit and/or the associated steering assembly to change, taking the well bore away from its intended path. As a result, corrective steering has to be done in order to bring the well bore back to the intended path. The more frequently this deviation and corrective steering occurs, the less straight and more tortuous the well bore becomes. A more tortuous well bore makes it harder to effectively transfer the apparent WOB applied at the surface along the drill string to the drill bit, due to engagement or interaction between the drill string and the side wall of the well bore, and makes it harder subsequently to drill further or to run tools, casing and the like along the well bore.
A steerable bottom hole assembly (BHA) for directional drilling typically employs a fixed cutter drill bit (also known as a drag bit), in combination with a steering assembly. The BHA or steering assembly may also include equipment for detecting and measuring the tool position and orientation, such as a measuring-while-drilling (MWD) tool. Downhole motors are also often employed between the steering assembly and the drill bit, such as the so-called Moineau motors which are driven by the flow of drilling mud used in drilling operations.
A fixed cutter drill bit typically includes a bit body formed with several blades arranged around the longitudinal axis of the bit body, and a plurality of super-abrasive cutters, such as polycrystalline diamond compact (PDC) or thermally stable PCD (TSP) cutters, mounted on the blades so as to engage with and cut into the rock formation being drilled as the bit body is rotated. PDC cutters are most usually formed as a disc-shaped diamond table to act as a cutting face and supported on a cylindrical tungsten carbide (WC) substrate. The cutters are most often mounted on the blades of the bit body by brazing the cutters into pockets formed in the blades.
Junk slots are formed between the blades, with nozzles formed near the apex of each junk slot, so that drilling mud can be circulated from the surface, along passages in the drill string, out of the nozzles, and back up to the surface along the annulus between the drill string and the side wall of the well bore. This circulating fluid cools the drill bit and cutters, and carries the rock cuttings cut by the rotating cutters up to the surface, where the drilling mud is filtered to remove the cuttings and re-circulated.
When drilling a well bore, it is normally desirable to achieve a high rate of penetration (ROP), i.e., the distance drilled into the rock per unit time. To obtain a high rate of penetration, it is desirable to increase the rate of rotation of the drill bit and the volume of rock cut and removed with each rotation of the drill bit. Accordingly, fixed cutter drill bit designs seek to increase the total area of engagement between the cutting faces of the cutters and the rock formation, so as to increase the volume of rock being removed with each rotation of the drill bit, as well as employing advanced hydraulic design of the nozzles, blades and junk slots to ensure that sufficient fluid is circulated to cool the cutters and carry the cuttings away.
The cutters are typically distributed along the front and outer edges of the blades so that the radial positions of the cutters on the several blades vary as between each blade, so that the volumes of revolution defined by the plurality of cutters as the blades rotate overlap. In this way, each cutter is offset from every other cutter, so that it will cut virgin rock as it rotates and not merely track another cutter at the same radial position, and the plurality of cutters on the several blades between them obtain a substantially unbroken coverage across the rock face at the bottom of the well bore being drilled.
One feature of such designs is the depth to which each cutter is intended to cut into and engage with the rock face. By increasing the weight-on-bit (WOB), the cutters will be pushed deeper into the rock face, thereby increasing the depth-of-cut (DOC); however, with increased engagement of the cutters into the rock face, there is an attendant increase in the TOB that must be applied to rotate the drill bit, to overcome the reactive torque which the rock face imparts to the drill bit as the teeth engage with it. Similarly, increasing the DOC increases the work that each cutter must do, the amount of heat generated by the cutters, and the volume of cuttings that must carried away.
In this way, it can be understood that an increase in the depth of engagement of the cutters into the rock formation will lead to a corresponding increase in the reactive torque. An increase in the depth of engagement of the cutters into the rock face may occur, for example, either as a result of an increase in the WOB or due to the drill bit encountering a reduction in the compressive rock strength of the formation at the rock face, such as when moving into a zone of a different rock type. (Unless otherwise stated or dictated by context, references herein to the compressive rock strength refer to the confined compressive rock strength.)
The resulting fluctuations in the TOB, as noted above, are liable to cause the contact face (tool face) of the drill bit to jump or twist out of proper orientation and engagement with the rock face, and so misalign the drill bit and/or the associated steerable BHA with respect to the intended path of the well bore. Equally, if the cutters become over-engaged with the rock formation being drilled, the volume of cuttings being removed may exceed the capacity of the circulating drilling mud to clear the cuttings away from the cutters and junk slots, leading to so-called bit balling. Alternatively, the reactive torque on the bit may simply become too great for the associated downhole motor to continue to turn the bit, causing the bit to stall, or even so large as to damage the cutters, drill bit or other components of the BHA.
Variations in the compressive strength of the rock formation being drilled occur naturally, and the drilling operator may attempt to compensate for these by making corresponding adjustments to the WOB. Nevertheless, these adjustments will often lag the actual transition of the drill bit from one rock type to the next.
Furthermore, it is usually not possible in practice, in directional drilling, to transfer all of the apparent WOB applied at the surface all the way to the drill bit, due to the contact which occurs between the drill string and the well bore side wall. This can result in a phenomenon known as “stick and slip”, where some part of the drill string, such as a stabilizer, catches on the side wall of the well bore as it navigates the curved path of the well bore, causing the drill string to stick in place and partially resist the applied WOB. A reduced WOB is then apparent at the tool face. When the stuck part of the drill string is then dislodged, for example as the stabilizer clears a bend in the well bore, the resistance to the applied WOB suddenly drops, and the apparent WOB at the tool face experiences a corresponding sudden increase. In addition to this, the problem may also be aggravated by drill string bounce, which is a similar phenomenon whereby the elasticity of the drill string causes erratic variation of the apparent WOB applied to the drill bit, with consequent over-engagement of the cutters.
Various approaches have been taken in the past in order to attempt to mitigate the above-mentioned problems, in particular by limiting or controlling the depth-of-cut (DOC) of the cutters into the formation. More specifically, various techniques have been used in order to try to prevent the cutters from over-engaging with the rock face when the WOB tends to force the cutters too deeply into the formation being drilled.
One technique is to use a variety of depth-of-cut control (DOCC) features to limit the DOC to a nominal maximum. The three main types of DOCC features can be summarised as follows.
The first type of DOCC features are a variety of structures or protrusions immediately trailing or preceding the PDC cutters (with respect to the intended direction of bit rotation) to protect the cutters or their mounting structures. Structures rotationally trailing the PDC cutters are disclosed, for example, in U.S. Pat. Nos. 4,889,017; 4,991,670; 5,244,039; and 5,303,785. Structures rotationally preceding the PDC cutters are disclosed, for example, in U.S. Pat. Nos. 3,153,458; 4,554,986; 5,199,511; and 5,595,252. These structures seek to limit the exposure of the associated PDC cutters by coming into contact the rock face behind the cutters, thereby limiting the maximum DOC to the height that the cutter extends beyond the protrusion. However, when used alone, these DOCC features may be prone to suffer relatively large variations in the maximum DOC when either the DOCC structure or the cutter itself becomes worn by abrasion against the rock face. When the DOCC structure is worn relative to the cutter, the DOC will increase, with the attendant problems noted above. When the cutter is worn relative to the DOCC structure, the maximum DOC is reduced, which may result in a reduced ROP for the cutter.
The second type of DOCC feature is a relatively deep cutter pocket formed on the bit body, so that the cutters effectively become partially buried when they are fixed into the cutter pockets, thereby limiting the exposure of the cutters. This may have a similar effect to the provision of trailing or preceding structures of the first DOCC feature type, but may render the drill bit less adaptable for drilling formations of different, relatively hard or soft, rock types, and will tend to restrict design freedom as regards the orientation and placement of cutters on the bit body.
The third type of DOCC feature, as disclosed in U.S. Patent Application Publication No. US 2006/0278436 A1, is a bearing surface structure located rotationally in advance of the PDC cutters and arranged to transfer the WOB directly to the rock face once the associated cutters have become engaged up to the maximum DOC. The cutters will then not exceed the maximum DOC, unless the WOB applied through the bearing surface is sufficient to exceed the compressive rock strength of the formation. To prevent this, the total area of the bearing surfaces must be designed to be sufficiently large to distribute the WOB without exceeding the compressive rock strength for the formation which it is intended to drill. However, the need to provide a sufficiently large bearing surface area can place unfavourable constraint on the bit design, including the design of the blades and cutter placement, and may also have a negative impact on the hydraulic behaviour of the drilling fluid in the junk slots and at the interface between the drill bit and the rock face being drilled. These constraints may be exacerbated for drill bits intended for drilling relatively soft (low compressive strength) rock formations, or for relatively small diameter drill bits.
Another related technique to control the DOC is to mount some or all of the cutters to the bit body with a less aggressive angle or orientation relative to the cutting direction of the cutter as the drill bit rotates. Cutter aggressiveness is a measure of the degree to which a cutter will tend to bite into the rock face, as opposed to tending to push away from the rock face as the bit rotates. By mounting cutters so that they have a positive or forward rake, they will tend to dig into the rock face (effectively pulling the bit into the rock as they cut it), thereby tending to remove more formation material and generating a higher reactive torque. Cutters mounted with a positive rake angle are thus more aggressive. Cutters with a negative rake angle, or backrake, tend to push away from the formation, trying to slide over it rather than cutting through it, and so are less aggressive.
As will be self-evident, cutters mounted at an aggressive positive rake angle will be more prone to generate a large reactive torque as a result of a sudden increase in WOB, whereas cutters mounted with a backrake will tend to suffer less variation in the reactive torque as a result of fluctuations in the WOB. Backraked cutters have thus been used, particularly for steerable drill bits, in order to make the drill bit less susceptible to WOB fluctuations. However, cutters with a significant back rake angle have been found not to be effective for drilling through softer (low compressive strength) rock formations. In order to try to achieve a balance between ROP and behaviour of the bit under WOB fluctuations, bits using cutters having a mixture of positive, negative and/or neutral backrake angles have been suggested, for example in U.S. Pat. No. 5,314,033.
As can be appreciated from the foregoing, it would be desirable to provide a drill bit design solution, in particular for directional drilling, that will mitigate the undesirable response tendencies of the drill bit to fluctuations in WOB, while preserving design freedom and maintaining acceptable WOB, ROP and hydraulic performance capability of the drill bit.
Each of the aforementioned published patents and patent applications is hereby incorporated herein in its entirety.